Method for removing iron sulfide scale

ABSTRACT

A method of removing an iron sulfide scale from a surface in fluid communication with a wellbore and/or subterranean formation comprising contacting the iron sulfide scale on the surface with a composition to dissolve the iron sulfide scale in the composition. The composition comprises (a) at least one chelating agent selected from the group consisting of DTPA, EDTA, HEDTA, GLDA, CDTA, and MGDA, and salts thereof, and (b) at least one converting agent selected from the group consisting of potassium carbonate (K 2 CO 3 ), potassium formate (HCOOK), potassium hydroxide (KOH), potassium chloride (KCl), cesium formate (HCOOCs), and cesium chloride (CsCl). In the composition, the weight ratio of (a):(b) lies in the range 7-60:2-20.

BACKGROUND OF THE INVENTION

Technical Field

The present disclosure relates to methods of removing iron sulfide scaledeposits from surfaces in fluid communication with a wellbore and/orsubterranean formation, and more particularly to methods for removingsuch deposits with a composition comprising at least one chelating agentand at least one converting agent.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, is neitherexpressly nor impliedly admitted as prior art against the presentinvention.

During the production stage of a wellbore, fluids (e.g., gas, oil,steam, hot water, etc.) are generally produced from the wellbore, andscale can develop in the wellbore, subterranean formation and/or onequipment associated with the wellbore, such as downhole equipment(e.g., casings, production tubing, mandrels, pipes, pumps, etc.) andsurface equipment (e.g., pumps, heating turbines, heat exchangers,etc.). Whenever the wellbore produces water, or when water injection isused to enhance the recovery of the natural resource, there is thepossibility that scale will form. One type of scale includes ironsulfide compounds, which have a physical appearance of amorphous solidparticles capable of absorbing water and oil.

Hydrogen sulfide, H₂S, is a naturally occurring contaminant of fluidsthat is encountered in many industries, including the oil and gasindustry and the paper industry. The corrosive nature of H₂S causes theaccumulation of particulate iron sulfide. Iron sulfide becomes entrainedin hydrocarbons, glycol, salts, and the like to form scale deposits onthe surfaces of conduits such as pipelines. Such deposits present asignificant problem because the deposits hinder accurate determinationsof pipeline structural integrity and the pipelines must be cleanedphysically.

Given the various chemical and physical conditions that go into theforming of iron sulfide scales, several forms can be found in a givensection of a wellbore and a pipeline. It is seldom that a single type ofiron sulfide scale exists; but more generally it is a mixture of ironsulfide scales, including pyrrhotite (Fe₇S₈), troilite (FeS), marcasite(FeS₂), pyrite (FeS₂), greigite (Fe₂S₄), and mackinawite (Fe₉S₈).

The iron sulfide particles can adhere to the internal surfaces of awellbore, pipeline networks, and associated process equipment. Thephysical characteristic of the iron sulfide scale deposits can vary froma viscous, oil coated mass to a dry black powder form. The buildup ofiron sulfide scale deposits over time can lead to a range of operationalproblems at a wellbore's completion and production stages, frominhibiting the performance of downhole tools to inducing formationdamage and plugging of associated equipment, whether such equipment islocated downhole or at the surface of the wellbore. The iron sulfidescale deposits may block flow of the natural resources by cloggingperforations or forming a thick lining in the production tubing. Theiron sulfide scale deposits can also coat and damage wellbore equipment,such as heating turbines, heat exchangers, safety valves, casings,production tubing, mandrels, pipes, separators, pumps, etc. If the ironsulfide scale deposits are not removed, the wellbore production capacitycan diminish drastically, and in some cases the iron sulfide scaledeposits can cause the wellbore production to be shut down for a periodof time. Additionally, the iron sulfide scale deposits can lead toincreased corrosion rates within pipeline networks and interference inthe safe operation of pipeline valving systems, potentially leading tocatastrophic system failures. As a result, in the oil industry, the ironsulfide scale deposits are a major source of economic loss. The depositsobstruct the flow of oil in wells, in the adjacent strata and inpipelines as well as in processing and refinery plants. Further, suchdeposits tend to stabilize oil-water emulsions that tend to form duringsecondary oil recovery.

Methods have been developed to decrease and remove iron sulfide scaledeposits, including batch chemical cleaning, continuous chemicalcleaning, and mechanical efforts, such as milling, high pressure waterjetting, and sand blasting. The use of a strong acid, such as 10-20 wt %HCl, is the simplest way to dissolve iron sulfide scales, however, it isineffective in dissolving the pyrite (FeS₂) and marcasite (FeS₂) formsof the iron sulfide scales. Additionally, using a strong acid generateslarge volumes of highly toxic H₂S gas, which is an undesirableby-product. The strong acid can also have corrosive effects on thewellbore equipment and may damage the formation. Using an oxidizingagent may avoid such toxicity hazards but produces oxidation products,including elemental sulphur which is corrosive to pipes. Another agentfor treating such deposits is acrolein, but it also has health, safetyand environmental problems. Mechanical methods, such as milling andwater jetting using pressures in excess of 140 MPa (with and withoutabrasives), generally require that each pipe or piece of equipment betreated individually with significant levels of manual intervention,which is both time consuming and expensive, but sometimes also fail tothoroughly remove the iron sulfide scale deposits.

Therefore, there is an urgent need for an iron sulfide removalcomposition and method which is effective and efficient for all forms ofiron sulfide scales, particularly the pyrite and marcasite forms thatare insoluble in strong acid, non-corrosive to the equipment, and lowcost, and which does not cause damage to the formation and theenvironment.

BRIEF SUMMARY OF THE INVENTION

According to a first aspect, the present disclosure relates to a methodof removing an iron sulfide scale from a surface in fluid communicationwith a wellbore and/or subterranean formation. The method comprisescontacting the iron sulfide scale on the surface in fluid communicationwith the wellbore and/or subterranean formation with a composition todissolve the iron sulfide scale in the composition. The compositionincludes (a) at least one chelating agent selected from the groupconsisting of DTPA, EDTA, HEDTA, GLDA, CDTA, and MGDA, and saltsthereof, and (b) at least one converting agent selected from the groupconsisting of potassium carbonate (K₂CO₃), potassium formate (HCOOK),potassium hydroxide (KOH), potassium chloride (KCl), cesium formate(HCOOCs), and cesium chloride (CsCl). In the composition, the weightratio of (a):(b) lies in the range 7-60:2-20.

In one or more embodiments, the method further comprises acidifying thecomposition containing the dissolved iron sulfide scale to form aprecipitant of the at least one chelating agent and a precipitant of atleast one insoluble iron salt, isolating the precipitant of the at leastone chelating agent and the precipitant of at least one insoluble ironsalt from the composition, selectively dissolving the precipitated atleast one chelating agent in another composition, and removing theprecipitated at least one insoluble iron salt from the anothercomposition.

In one or more embodiments, the composition comprises (a) at least onechelating agent selected from the group consisting of DTPA, EDTA, HEDTA,and CDTA, and salts thereof, and the composition has a pH ranging fromabout 8 to 14.

In one or more embodiments, the iron sulfide scale is at least oneselected from the group consisting of a scale of pyrrhotite (Fe₇S₈), ascale of troilite (FeS), a scale of marcasite (FeS₂), a scale of pyrite(FeS₂), a scale of greigite (Fe₂S₄), and a scale of mackinawite (Fe₉S₈).

In one or more embodiments, at least about 70% of the iron sulfide scaleis removed from the surface in fluid communication with the wellboreand/or subterranean formation. In some embodiments, at least 50 ml ofthe composition is used per gram of the iron sulfide scale.

In one or more embodiments, the wellbore has a bottom hole temperaturein the range of from about 100° F. to about 400° F.

In one or more embodiments, the contacting lasts at least about 24hours. In some embodiments, at least 50 ml of the composition is usedper gram of the iron sulfide scale.

In one or more embodiments, the composition further comprises at leastone surfactant.

In one or more embodiments, (a) and (b) of the composition are dissolvedin an aqueous solution as a continuous phase, and the compositionfurther comprises (c) a liquid aromatic solvent as a dispersed phase forsolid or semisolid organic materials and (d) an effective amount of atleast one emulsifier to form an emulsion. In some embodiments, theliquid aromatic solvent comprises at least one selected from the groupconsisting of toluene, benzene, and xylene. In some embodiments, the atleast one emulsifier comprises at least one selected from the groupconsisting of a polyamide emulsifier having the formulaR³O—C(O)—R⁴—C(O)—N(R¹)—(CH₂)_(n)—NH—C(O)—R² (where R¹ and R² areindependently selected from C₁₀-C₂₄ alkylene groups, R³ is a hydrogen ora C₁-C₅ alkyl group, R⁴ is a C₁-C₅ alkyl/alkene group, and n is aninteger of from 2-5), a phosphate ester of an ethoxylated straight chainalcohol containing 8 to 10 carbon atoms and containing ethylene oxide inreacted form at a 4:1 or greater molar ratio relative to the straightchain alcohol, and a phosphate ester of an ethoxylated tridecyl alcoholcontaining ethylene oxide in reacted form at a 6:1 or greater molarratio relative to the tridecyl alcohol. In some embodiments, the volumeproportion of the aqueous solution as the continuous phase to the liquidaromatic solvent as the dispersed phase ranges from about 80:20 to about50:50.

In one or more embodiments, the wellbore is present in at least one ofan oil well, a gas well, a production well, an injection well, anaturally flowing well, an artificially lifted well, a high temperaturewell, a steam assisted gravity drainage well, a steam injector well, anda geothermal well.

In one or more embodiments, the surface in fluid communication with thewellbore and/or subterranean formation comprises a surface of an oiland/or gas reservoir, a geological surface, and/or a surface of at leastone piece of equipment selected from the group consisting of heatingturbines, heat exchangers, safety valves, casings, production tubing,mandrels, pipes, separators, pumps, tubulars, vessels, completionequipment, screens, and downhole tools.

According to a second aspect, the present disclosure relates to apreferred method of removing an iron sulfide scale from a surface influid communication with a wellbore and/or subterranean formation. Themethod comprises contacting the iron sulfide scale on the surface influid communication with the wellbore and/or subterranean formation witha composition to dissolve the iron sulfide scale in the composition. Theiron sulfide scale is at least one selected from the group consisting ofa scale of pyrrhotite (Fe₇S₈), a scale of troilite (FeS), a scale ofmarcasite (FeS₂), a scale of pyrite (FeS₂), a scale of greigite (Fe₂S₄),and a scale of mackinawite (Fe₉S₈). The composition includes (a) DTPAand/or salts thereof, and (b) potassium carbonate (K₂CO₃). In thecomposition, the weight ratio of (a):(b) lies in the range 7-60:2-20,and the pH of the composition is about 11-14.

In one or more embodiments, the method further comprises treating thecomposition containing the dissolved iron sulfide scale with aneffective amount of at least one iron reducing agent to reduce Fe³⁺ toFe²⁺, acidifying the composition containing the dissolved iron sulfidescale to form a precipitant of DTPA and/or a precipitant of at least oneinsoluble iron salt, isolating the precipitated DTPA and/or theprecipitated at least one insoluble iron salt from the composition,selectively dissolving the precipitated DTPA in another composition,and/or removing the precipitated at least one insoluble iron salt fromthe another composition.

In one or more embodiments, the method further comprises sonicating thecomposition which forms a liquid phase in contact with the iron sulfidescale at a frequency of about 1-20 kHz and at a power of about 1-100 kWfor a duration effective to remove or reduce the iron sulfide scale.

In one or more embodiments, the composition further comprises (c) atleast one formate salt selected from the group consisting of potassiumformate and cesium formate. In the composition, the weight ratio of(a):(b):(c) lies in the range 7-60:2-20:2-20.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 is a picture showing the mixture of the pyrite scale particlesand the removing composition in a flask at the beginning of the soakingtreatment according to Example 1.

FIG. 2 is a top view of the mixture in the flask displayed in FIG. 1according to Example 1, showing the input pyrite scale particles presentin the mixture at the beginning of the soaking treatment.

FIG. 3 is a picture showing the mixture of the pyrite scale particlesand the removing composition in the flask after 24 hours of soakingtreatment at 70° C. according to Example 1.

FIG. 4 is a top view of the mixture in the flask displayed in FIG. 3according to Example 1, showing the reduced quantity of the pyrite scaleparticles remaining in the mixture in the flask after 24 hours ofsoaking treatment as compared with the quantity of the input pyritescale particles shown in FIG. 2.

FIG. 5 is a picture showing the mixture of the pyrite scale particlesand the removing composition in the flask after 48 hours of soakingtreatment at 70° C. according to Example 1.

FIG. 6 is a top view of the mixture in the flask displayed in FIG. 5according to Example 1, showing the further reduced quantity of thepyrite scale particles remaining in the mixture in the flask after 48hours of soaking treatment as compared with the quantity of the pyritescale particles remaining after 24 hours of soaking treatment shown inFIG. 4.

FIG. 7 is a graphical presentation of the pyrite scale removalefficiencies of the removing composition comprising DTPA and potassiumcarbonate (DTPA/Converter), DTPA alone, a low pH BDCA solution, and 20wt % HCl.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Disclosed herein are methods for removing an iron sulfide scale from asurface in fluid communication with a wellbore and/or subterraneanformation.

According to the first aspect of the present disclosure, the methodcomprises contacting the iron sulfide scale on the surface in fluidcommunication with the wellbore and/or subterranean formation with acomposition to dissolve the iron sulfide scale in the composition. Thecomposition comprises (a) at least one chelating agent selected from thegroup consisting of DTPA, EDTA, HEDTA, GLDA, CDTA, and MGDA, and saltsthereof, and (b) at least one converting agent selected from the groupconsisting of potassium carbonate (K₂CO₃), potassium formate (HCOOK),potassium hydroxide (KOH), potassium chloride (KCl), cesium formate(HCOOCs), and cesium chloride (CsCl). In some embodiments, the at leastone converting agent may also include a bicarbonate, for example,potassium bicarbonate (KHCO₃).

The at least one chelating agent in the composition has a molecularstructure capable of enveloping and/or sequestering a certain type ofion, including iron cations, in a stable and soluble complex. The atleast one converting agent in the composition assists in the dissolutionof the iron sulfide scale by converting an extremely insoluble ironsulfide salt, e.g. FeS₂ and Fe₇S₈, to a more soluble salt, and/orincreases the efficiency of sequestration of the scaling cations.

In some embodiments, the iron sulfide scale that can be removed by themethod includes a scale of pyrrhotite (Fe₇S₈), a scale of troilite(FeS), a scale of marcasite (FeS₂), a scale of pyrite (FeS₂), a scale ofgreigite (Fe₂S₄), a scale of mackinawite (Fe₉S₈), and a combinationthereof.

The disclosed method can remove at least a portion of an iron sulfidescale from a surface in fluid communication with a wellbore and/orsubterranean formation. The surface includes a natural surface (e.g.,geological surface, surface of an oil and/or gas reservoir), or asurface of artificially placed or deliberately introduced materials(e.g., wellbore equipment), whose surface is also prone to scaledeposition, or a surface in a subterranean formation, although theremoval of scale from other surfaces of the type disclosed herein isalso contemplated. In an embodiment, the method may be used for theremoval of an iron sulfide scale deposits/accumulations or scale from asurface of the wellbore and/or subterranean formation. In someembodiments, the method may be used for the removal of an iron sulfidescale from the wellbore equipment (e.g., downhole equipment, surfaceequipment associated with the wellbore) surfaces that are in fluidcommunication with the wellbore and/or subterranean formation such thatfluids (e.g., produced fluids) travelling to and/or from the wellboreand/or subterranean formation contact said surfaces. Non-limitingexamples of wellbore equipment that might accumulate iron sulfide scaleon one or more surfaces include heating turbines, heat exchangers,safety valves, casings, production tubing, mandrels, pipes, separators,pumps, tubulars, vessels, completion equipment (e.g., screens, etc.),downhole tools and any other piece of equipment that might come incontact with a wellbore fluid, whether such fluid is produced or part ofa servicing fluid. In other embodiments, the method may be used for theremoval of an iron sulfide scale from any surface that might come incontact with a produced natural resource (e.g., water, steam, hot water,oil, gas, etc.).

In some embodiments, the at least one chelating agent of the compositionis selected from the group consisting of K₅-DTPA, K₄-EDTA, K₃-HEDTA,K₄-GLDA, K₄-CDTA, K₃-MGDA, Na₅-DTPA, Na₄-EDTA, Na₃-HEDTA, Na₄-GLDA,Na₄-CDTA, and Na₃-MGDA. Further, the at least one chelating agent may bea mixed salt chelating agent, for instance, Na₂K₂-EDTA, etc.

Among the chelating agents suitable for the composition are polydentatechelators, such as DTPA, EDTA, and CDTA. Polydentate chelators formmultiple bonds with metal ions, including iron cations, in complexingwith the metal. For example, DTPA is octadentate, however, it usuallyforms less than eight bonds with transition metals that include iron.EDTA is hexadentate, forming a total of six bonds with Fe³⁺. BesidesDTPA, EDTA, HEDTA, GLDA, CDTA, and MGDA, and salts thereof, otherchelating agents may also be suitable for the composition. Inparticular, the selection of the chelating agents may be related to thespecificity of the chelating agents to the iron cations, the log K value(where K is the stability constant indicating the strength of thecomplex formed between the metal ion and the chelating agent), theoptimum pH of the composition when used to dissolve the iron sulfidescale, and the commercial availability of the chelating agents. Thehigher the log K value, the more tightly the metal ion is bound to thechelating agent and the more likely that the complex will be formed. Forexample, based on the log K values, PDTA(1,3-propylenediaminetetraacetic acid) may be another suitable chelatingagent for the composition, since its log K values for Fe²⁺ and Fe³⁺ arehigher than the corresponding log K values of HEDTA and GLDA.

In some embodiments, the concentration of the at least one chelatingagent is about 7-60%, preferably about 10-40%, more preferably about10-30%, or more preferably about 15-25%, of the total weight of thecomposition.

In some embodiments, the concentration of the at least one convertingagent is about 2-20%, preferably about 3-18%, more preferably about4-15%, or more preferably about 5-9%, of the total weight of thecomposition.

In some embodiments, the composition comprises at least one chelatingagent selected from DTPA, EDTA, HEDTA, GLDA, CDTA, and MGDA, and saltsthereof, and potassium carbonate (K₂CO₃) as the converting agent. Inother embodiments, the composition comprises the at least one chelatingagent and a combination of the converting agents which preferablyincludes potassium carbonate, such as a combination of potassiumcarbonate and potassium formate (and/or cesium formate), a combinationof potassium carbonate, potassium formate (and/or cesium formate), andpotassium hydroxide, and a combination of potassium carbonate andpotassium chloride (and/or cesium chloride). The use of carbonateconverting agent may have a beneficial effect on the amount of the ironsulfide scale which can be removed with a given volume of thecomposition particularly where the iron sulfide scale exists in aparticular form and downhole conditions of carbon dioxide partialpressure and/or organic acids provide acid conditions for produced waterwhich allows converted, non-chelated iron sulfide scale to be removedafter the well has been returned to flowing conditions.

In some embodiments, the composition has a weight ratio of (a):(b) inthe range 7-60:2-20, preferably 10-40:3-18, preferably 10-30:4-15, ormore preferably 15-25:5-9.

In some embodiments, the composition comprises (a) at least onechelating agent selected from the group consisting of DTPA, EDTA, HEDTA,and CDTA, and salts thereof, and the composition has a pH ranging fromabout 8 to 14, preferably from about 10 to 12, or more preferably fromabout 11 to 14.

In other embodiments, the composition comprises (a) at least onechelating agent selected from the group consisting of GLDA and MGDA, andsalts thereof, and the composition has a pH ranging from about 2 to 6,preferably from about 3 to 5, or more preferably from about 3 to 4.

In some embodiments, a high power ultrasound, low or high frequencysonic energy, or a low power ultrasound may be used in conjunction withthe disclosed method to increase the rate of dissolution of the ironsulfide scale by the composition disclosed herein. The ultrasoundtreatment increases surface agitation and the contact of the compositionin pores within the iron sulfide scale by creating a pressure wave whichforces the composition in and out of the scale and prevents thecomposition from becoming saturated in the low mixing potential areas.In one embodiment, a low power (e.g. 1-2 kW) and frequency (e.g. 1-2kHz) ultrasound can be delivered via a piezoelectric or magnetostrictivetransducer inserted directly into a well in the vicinity of iron sulfidedeposits. The well may be flooded with the composition or other fluidscontaining the components of the composition. In another embodiment, arelatively high frequency (e.g. 20 kHz or higher) and/or high power(e.g. 10-100 kW or greater) ultrasound can be delivered via a wellsonication device, such as a QVI siren available from Quantum Vortex,Inc. (State College, Pa., USA). In one embodiment, the sonication deviceis small enough to fit standard wellbore casings (e.g. 6″ or 7.5″wellbore casings) and be employed to sonicate the entire well or aparticular section of the well. In another embodiment, the sonicationdevice is located outside a well and produces a high ultrasonic powersufficient to overcome attenuation en route from the well head to thetarget zone having iron sulfide scale deposits. The well may likewise beflooded with the composition or other fluids containing the componentsof the composition to establish a continuous liquid phase for efficientultrasonic operation. The duration of the sonication can be short, e.g.tens of hours, or continuously.

The method of the present disclosure can be implemented in numerousdifferent ways and environments. In one embodiment, the method isimplemented by introducing the composition to the wellbore and/orsurrounding formation. In some embodiments, the composition is appliedto the wellbore and/or surrounding formation simultaneously withdrilling fluids or muds, spacer fluids, lost circulation fluids, washingfluids, sweeping fluids, fracturing fluids, acidizing fluids, completionfluids, filter cake removal fluids, or cement slurries. In otherembodiments, the composition is incorporated in the above mentionedfluids or slurries. In other embodiments, the composition is appliedindependently of the above mentioned fluids or slurries.

In a well drilling operation, a pumping system may be used to introduceand circulate the composition or a fluid containing the components ofthe composition down the drill string of the well to remove iron sulfidescale and/or prevent iron sulfide scale formation. The composition orthe fluid then exits through the rotating drill bit and flows back tothe surface via the annular space formed between the borehole wall andthe drill string. In this situation, the composition or the fluid mayalso (a) provide support to the borehole wall and (b) prevent or, incase of under balanced drilling (UBD), control formation fluids orgasses from entering the well, with the pressure the composition or thefluid exerts against the wellbore inside wall that is mainly built-up ofa hydrostatic part, related to the weight of the composition/fluidcolumn, and a dynamic part related to frictional pressure losses causedby, for instance, the composition/fluid circulation rate or movement ofthe drill string. In one embodiment, the composition or the fluidcontaining the components of the composition is pumped into the wellboreat such a rate or pressure that the pressure of the composition or thefluid against the wellbore inside wall, termed the “fluid pressure”herein, does not exceed the formation fracture pressure or formationstrength, whether the composition or the fluid is static or circulatedduring drilling operations. If the formation strength is exceeded,formation fractures will occur which will create drilling problems suchas fluid losses and borehole instability. On the other hand, inoverbalanced drilling, the fluid pressure in the well is alwaysmaintained above the pore pressure to avoid formation fluids enteringthe well, while during under balanced drilling, the fluid pressure inthe well is maintained just below the pore pressure to controllablyallow formation fluids entering the well. In some embodiments, theinjection pressure for the composition or the fluid containing thecomponents of the composition ranges from about 5,000 psi to 15,000 psi.In some embodiments, an injection pressure of about 5,000-15,000 psi ora different range is maintained to keep the fluid pressure slightlybelow or above the pore pressure but not exceeding the formationstrength. In other embodiments, when the composition or the fluidcontaining the components of the composition is continuouslycirculating, or alternately circulating and statically soaking with theiron sulfide scale, the circulation rate, which affects the fluidpressure, may also be adjusted along with the injection pressure to keepthe fluid pressure slightly below or above the pore pressure but notexceeding the formation strength.

In one embodiment, the components of the composition are combined at thewell site; alternatively, the components of the composition are combinedoff-site and are transported to and used at the well site. The resultingcomposition may be pumped downhole where it may function as intended(e.g., remove at least a portion of an iron sulfide scale deposit on asurface in fluid communication with the wellbore and/or subterraneanformation).

In one embodiment, the method may be used for the removal of an ironsulfide scale in any suitable stage of a wellbore's life, such as forexample, during a drilling operation, completion operation, productionstage, etc. In some embodiments, the disclosed method may be used forremoving iron sulfide scale deposits from any surfaces in fluidcommunication with the wellbore by placing the composition downhole andcontacting the composition with the iron sulfide scale to remove all ora portion thereof, concurrent with and/or subsequent to drillingoperations where iron sulfide scales are formed on those surfaces. Inother embodiments, concurrent with and/or subsequent to drillingoperations where scale is formed and/or likely to be formed on adownhole surface, the composition of the disclosed method (or componentsthereof) may be combined with an aqueous based drilling fluid toprevent/reduce the formation of scale and/or remove all or a portion ofexisting iron sulfide scale.

In some embodiments, the disclosed method may be utilized in conjunctionwith a formation evaluation operation such as electronically logging thewellbore. For example, in one embodiment, the wellbore may be evaluatedvia electronic logging techniques following sufficient contact betweenthe iron sulfide scale and the composition to remove all or a portion ofthe iron sulfide scale. In such an embodiment, a method of evaluating aformation utilizing the composition of the disclosed method maygenerally comprise circulating a drilling fluid during a drillingoperation (wherein an iron sulfide scale is formed during the drilling)and, upon the cessation of drilling operations and/or upon reaching adesired depth, removing the iron sulfide scale deposits from a downholesurface (e.g., a wellbore surface, formation surface, equipment surface,etc.) utilizing the composition of the disclosed method. Upon sufficientremoval of the iron sulfide scale deposits, logging tools may be runinto the wellbore to a sufficient depth to characterize a desiredportion of the subterranean formation penetrated by the wellbore.

In another embodiment, when desired (for example, upon the cessation ofdrilling operations and/or upon reaching a desired depth), the wellboreor a portion thereof may be prepared for completion. In completing thewellbore, it may be desirable to remove all or a substantial portion ofthe iron sulfide scale from any surfaces where the scale might have beendeposited, from equipment surface to formation surface.

In another embodiment, the disclosed method may comprise completing thewellbore. In such an embodiment, the wellbore, or a portion thereof, maybe completed by providing a casing string within the wellbore andcementing or otherwise securing the casing string within the wellbore.In such an embodiment, the casing string may be positioned (e.g.,lowered) into the wellbore to a desired depth prior to, concurrent with,or following provision of the composition and/or removal of the ironsulfide scale deposit. When the iron sulfide scale has been sufficientlydegraded and/or removed from the downhole surface (e.g., wellboresurface, equipment/casing surface, formation surface, etc.), thecomposition may be displaced from the wellbore by pumping a flushingfluid, a spacer fluid, and/or a suitable cementitious slurry downwardthrough an interior flowbore of the casing string and into an annularspace formed by the casing string and the wellbore walls. When thecementitious slurry has been positioned, the cementitious slurry may beallowed to set.

In another embodiment, the disclosed method may be utilized during theproduction stage of a wellbore. When the wellbore reaches the productionstage, whenever water is produced as the natural resource (e.g., steam,hot water, etc.) or along with the natural resource (e.g., oil), ironsulfide scale may deposit on any of the surfaces that the produced watercomes in contact with (e.g., formation surface, production tubing,etc.). The presence of the iron sulfide scale may slow down orcompletely stop production of the natural resource (e.g., oil, water,steam, etc.), so it may be advantageous to perform another operation ofiron sulfide scale removal. Accordingly, the composition of thedisclosed method may be placed downhole in association with a productionenhancement operation or service, where the composition is contactedwith a downhole surface (e.g., formation surface, wellbore surface,equipment surface, etc.) in fluid communication with the wellbore and/orsubterranean formation to remove all or a portion of scale therefrom andthereby increase the rate of production of resources from the well.

In some embodiments, the disclosed method may be used to prevent ironsulfide scale formation on various surfaces in fluid communication witha wellbore and/or subterranean formation, because of the ability of thecomposition to chelate dissolved metal ions, including the iron cations,present in the wellbore environment. In other embodiments, the disclosedmethod may be advantageously used to lower the risk of formation damagedue to the ability of the composition to effectively chelate Fe³⁺ ions,for example.

In one embodiment, the disclosed method may be advantageously used foriron sulfide scale removal operations in any suitable type ofsubterranean formation. Non-limiting examples of formations suitable forthis disclosure include sandstone, carbonate-containing formations,shale, or combinations thereof.

In one embodiment, the disclosed method may be advantageously used foriron sulfide scale removal operations in any suitable type of wellbore.Non-limiting examples of wellbores suitable for this disclosure includethose in an oil well, a gas well, a production well, an injection well,a naturally flowing well, an artificially lifted well, a hightemperature well, a steam assisted gravity drainage well, a steaminjector well, and a geothermal well.

In one embodiment, the composition of the disclosed method may be placeddownhole and allowed to circulate, for example, through the productiontubing, through the surface equipment (e.g., heating turbines, heatexchangers) associated with the wellbore; or in any other suitable wayto contact with the iron sulfide scale present on a surface in fluidcommunication with a wellbore and/or subterranean formation, to removeall or a portion of the scale therefrom and thereby increase the rate ofproduction of resources from the well. In another embodiment, thecomposition may be injected directly on the surface where the ironsulfide scale has been deposited. In another embodiment, the compositionmay be allowed to remain in contact with the iron sulfide scale for asufficient period of time, i.e. a soak-period, such that the compositionremoves all or a substantial portion of the scale from a surface wherethe scale may have been deposited.

The iron sulfide scale removal efficiency of the method is affected byseveral factors, including the particular chelating agents andconverting agents used, the presence or absence of additives such assurfactants, the concentration and/or amount of the chelating agents andconverting agents in the composition, the volume of the compositionused, the composition of the iron sulfide scale, the thickness of theiron sulfide scale, the temperature of the operational environment (e.g.the wellbore), the composition of the formation, the pressure of theformation, the diameter of the hole, the contact time of the compositionwith the iron sulfide scale, or combinations thereof. For example, withthe same well size and iron sulfide scale composition, the thicker theiron sulfide scale, the larger the amount and/or volume of thecomposition will be needed to dissolve the iron sulfide scale downhole,with the maximum volume of the composition being limited by the volumeof the well. Thus, the effect of iron sulfide scale thickness becomesmore significant in a relatively small-sized well, since the ratio ofthe iron sulfide scale mass to the composition volume may more likelyexceed the maximum solubility of the iron sulfide scale in thecomposition.

In some embodiments, the method removes at least about 70%, orpreferably at least about 80%, or more preferably at least about 90%,even more preferably at least 95%, yet even more preferably at least99%, of the iron sulfide scale from the surface in fluid communicationwith the wellbore and/or subterranean formation.

In some embodiments, the ratio of the composition volume used to contactthe mass of the iron sulfide scale is at least about 30 ml/g, preferablyat least about 50 ml/g, preferably at least about 75 ml/g, or preferablyabout at least 100 ml/g.

Various combinations of the chelating agents and converting agents inthe composition of the disclosed method may be operable under differentsuitable temperature ranges. As such, one or more of the chelatingagents in combination with one or more of the converting agents may beselected for inclusion in the composition such that the compositionexhibits a user and/or process-desired operable temperature range (e.g.,an ambient downhole temperature or bottom hole temperature for a givenwellbore). In some embodiments, the composition may exhibit an operabletemperature range of from about 65° F. to about 400° F., alternativelyfrom about 72° F. to about 385° F., or alternatively from about 88° F.to about 365° F.

In some embodiments, the disclosed method may be used for iron sulfidescale removal in wellbores having bottom hole temperatures (BHTs) in therange of from about 100° F. to about 400° F., alternatively from about200° F. to about 380° F., or alternatively from about 250° F. to about380° F.

In some embodiments, the method may be used for iron sulfide scaleremoval in ambient or relatively low temperature/ambient or relativelylow pressure wellbores having (i) a BHT no greater than 100° F., oralternatively no greater than 200° F., or alternatively no greater than300° F., and (ii) a borehole pressure no greater than about 20 psi, oralternatively no greater than about 100 psi, or alternatively no greaterthan about 200 psi, alternatively no greater than about 400 psi,alternatively no greater than about 1000 psi, alternatively no greaterthan about 3000 psi, alternatively no greater than about 5000 psi, oralternatively no greater than about 10,000 psi.

In some embodiments, the method may be used for iron sulfide scaleremoval in high temperature/high pressure wellbores having (i) a BHTgreater than about 300° F., alternatively greater than about 325° F., oralternatively greater than about 350° F.; and (ii) a borehole pressuregreater than about 10,000 psi, alternatively greater than about 12,500psi, or alternatively greater than about 15,000 psi.

In other embodiments, the method may be used for iron sulfide scaleremoval in extreme high temperature/high pressure wellbores having (i) aBHT greater than about 350° F., alternatively greater than about 375°F., or alternatively greater than about 400° F.; and (ii) a boreholepressure greater than about 15,000 psi, alternatively greater than about17,500 psi, or alternatively greater than about 20,000 psi.

In one embodiment, a sufficient amount and/or volume of the compositionthat has been placed in contact with the iron sulfide scale may beallowed to remain in contact with the iron sulfide scale for asufficient period of time such that the composition will remove all or asubstantial portion of the iron sulfide scale from any surfaces wherethe iron sulfide scale might have been deposited. In some embodiments,the composition may be allowed to remain in contact with the ironsulfide scale for a soak-period, for example, for a period of time of atleast about 1 hour, alternatively at least about 4 hours, alternativelyat least about 8 hours, alternatively at least about 16 hours,alternatively at least about 24 hours, alternatively at least about 36hours, alternatively at least about 48 hours, alternatively at leastabout 60 hours, alternatively at least about 72 hours, alternatively atleast about 84 hours, or alternatively at least about 100 hours. In oneembodiment, during such a “soak period,” the composition or a fluidcontaining the components of the composition within the wellbore and/orassociated wellbore equipment may remain in a substantially staticstate, for example, as opposed to a dynamic state in which circulationmay be present. In one embodiment, the wellbore may be shut-in while thecomposition remains in contact with the iron sulfide scale deposits.

In one embodiment, the composition in the method further comprises atleast one surfactant. The surfactant may function to improve thecompatibility of the composition with other fluids (e.g., formationfluids) that may be present in the subterranean formation and/or toenhance contact of the composition with one or more scaled surfaces. Insome embodiments, a surfactant may be used to enhance the reactivity ofthe composition by, for example, breaking any emulsions present from thedrilling fluid system or improving the interfacial interactions betweenthe iron sulfide scale deposit and the composition thereby allowing thecomposition to contact the scale deposit more easily. Non-limitingexamples of surfactants suitable for use in the composition includeethoxylated nonyl phenol phosphate esters, nonionic surfactants,cationic surfactants, anionic surfactants, amphoteric/zwitterionicsurfactants, alkyl phosphonate surfactants, linear alcohols, nonylphenolcompounds, alkyoxylated fatty acids, alkylphenol alkoxylates,ethoxylated amides, ethoxylated alkyl amines, betaines, methyl estersulfonates, hydrolyzed keratin, sulfosuccinates, taurates, amine oxides,alkoxylated fatty acids, alkoxylated alcohols, lauryl alcoholethoxylate, ethoxylated nonyl phenol, ethoxylated fatty amines,ethoxylated alkyl amines, cocoalkylamine ethoxylate, betaines, modifiedbetaines, alkylamidobetaines, cocamidopropyl betaine, quaternaryammonium compounds, trimethyltallowammonium chloride,trimethylcocoammonium chloride, or combinations thereof.

Commercial examples of surfactants that may be suitable for use in thepresent disclosure include without limitation CFS-485 casing cleaner,LOSURF-300M surfactant, LOSURF-357 surfactant, LOSURF-360 surfactant,LOSURF-400 surfactant, LOSURF-2000S surfactant, LOSURF-2000M surfactant,LOSURF-259 nonemulsifier, and NEA-96M surfactant. CFS-485 casing cleaneris a blend of surfactants and alcohols; LOSURF-300M surfactant is anonionic surfactant; LOSURF-357 surfactant is a nonionic liquidsurfactant; LOSURF-360 surfactant is a nonionic surfactant; LOSURF-400surfactant is a nonemulsifier; LOSURF-2000S surfactant is a blend of ananionic nonemulsifier and an anionic hydrotrope; LOSURF-2000M surfactantis a solid surfactant; LOSURF-259 nonemulsifier is a nonionic,nonemulsfier blend; and NEA-96M surfactant is a general surfactant andnonemulsifier; all of which are available from Halliburton EnergyServices, Inc.

Surfactants suitable for use in the present disclosure are described inmore detail in U.S. Pat. No. 7,992,656, which is incorporated byreference herein in its entirety. In an embodiment, the surfactants maybe present in the composition in an amount sufficient to preventincompatibility with formation fluids or wellbore fluids. In someembodiments, where liquid surfactants are used, the surfactants may bepresent in an amount of from about 0.1 wt. % to about 5 wt. %,alternatively from about 0.5 wt. % to about 4 wt. %, or alternativelyfrom about 1 wt. % to about 3 wt. %, based on the total weight of thecomposition. In other embodiments, where powdered surfactants are used,the surfactants may be present in an amount in the range of from about0.01 wt. % to about 1 wt. %, alternatively from about 0.05 wt. % toabout 0.5 wt. %, or alternatively from about 0.1 wt. % to about 0.3 wt.%, based on the total weight of the composition.

In some embodiments, it may be beneficial to add a surfactant to thecomposition as it is being pumped downhole, inter alia, to help reducethe possibility of forming emulsions with natural resources (e.g., oil)produced by the wellbore. In other embodiments, it may be beneficial topretreat the surfaces of the iron sulfide scale deposits with asurfactant fluid before treating the surfaces with the composition (withor without the surfactants) of the disclosed method. In someembodiments, microemulsion additives optionally may be included in thecomposition. Non-limiting examples of emulsion-minimizing surfactantsand microemulsion additives suitable for use in the present disclosureinclude PEN-88M surfactant, PEN-88HT surfactant, SSO-21E surfactant,SSO-21MW agent, and GASPERM 1000 service. PEN-88M surfactant is anonionic penetrating surfactant; PEN-88HT surfactant is ahigh-temperature surfactant; SSO-21E surfactant is a foaming surfactant;SSO-21MW agent is a foaming surfactant and GASPERM 1000 service is amicroemulsion; all of which are commercially available from HalliburtonEnergy Services, Inc.

In some embodiments, other additives such as corrosion inhibitors, claycontrol agents, pH control agents, lubricants, iron control agents, suchas erythorbic acid and stannous chloride, that reduce Fe³⁺ to Fe²⁺ toavoid precipitation of iron (III) compounds, and the like may beoptionally included in the composition.

In many instances, the iron sulfide scales may be coated and/orcommingled with solid or semisolid organic material which cannot bereadily removed by the composition comprising the chelating agents andconverting agents of the disclosed method. For example, in oil and gasproduction wells and petroleum processing equipment, iron sulfide scaledeposits may be coated with various organic deposits such as oils,asphaltenes, paraffins, tars, greases, and the like. To obtain the fullproduction capacity of wells and the like, it is advantageous to removethese deposits. In one embodiment, at least one aromatic solvent forremoving the organic deposits is used prior to or subsequent to treatingthe iron sulfide scale deposits with the composition comprising thechelating agents and converting agents. However, these multistagetreatments can be costly, time consuming and sometimes ineffective, andmay require consecutive rounds of treatments.

In a preferred embodiment, the composition comprising the chelatingagents and the converting agents dissolved in an aqueous solution as acontinuous phase may further comprise a liquid aromatic solvent as adispersed phase for solid or semisolid organic materials and aneffective amount of at least one emulsifier to form a stable emulsion.Iron sulfide scales having occluded organic materials (e.g., coatingsand/or intermediate coatings) are treated with the emulsion toeffectively remove both the iron sulfide scale and the organic materialin a one-stage treatment. Non-limiting examples of the liquid aromaticsolvent in the emulsion include toluene, both crude and refined,benzene, xylene, and the like. Non-limiting examples of the emulsifierinclude polyamide emulsifiers having the formulaR³O—C(O)—R⁴—C(O)—N(R¹)—(CH₂)_(n)—NH—C(O)—R² (where R¹ and R² areindependently selected from C₁₀-C₂₄ alkylene groups, R³ is a hydrogen ora C₁-C₅ alkyl group, R⁴ is a C₁-C₅ alkyl/alkene group, and n is aninteger of from 2-5) and typically used at a concentration of 0.5-1.5%of the total weight of the emulsion, as disclosed in U.S. Pat. No.8,163,675B2, which is incorporated herein by reference in its entirety;a phosphate ester of an ethoxylated straight chain alcohol containing 8to 10 carbon atoms and containing ethylene oxide in reacted form at a4:1 or greater molar ratio, preferably at a 6:1 or greater molar ratio,preferably at an 8:1 or greater molar ratio, or preferably at a 10:1 orgreater molar ratio, relative to the straight chain alcohol, andtypically used at a concentration of 0.5-5% of the total volume of theemulsion; and a phosphate ester of an ethoxylated tridecyl alcoholcontaining ethylene oxide in reacted form at a 6:1 or greater molarratio, preferably at an 8:1 or greater molar ratio, or preferably at a10:1 or greater molar ratio, relative to the tridecyl alcohol, andtypically used at a concentration of 0.5-5% of the total volume of theemulsion.

U.S. Pat. No. 6,006,831, which is incorporated herein by reference inits entirety, describes additional emulsifiers that may also be suitablefor the composition of the present disclosure. They include fatty acids,soaps of fatty acids (e.g., calcium soaps), and fatty acid derivativesincluding amidoamines, polyamides, polyamines, sulfonates,triglycerides, esters (such as sorbitan monoleate polyethoxylate,sorbitan dioleate polyethoxylate), imidazolines, alcohols andcombination derivatives of the above. The fatty acid soaps can be formedin situ by the addition of the desired fatty acid and a base, preferablylime. The above emulsifiers are generally used in amounts of about0.4-2.5 g/100 ml of the emulsion fluid.

The emulsion can be prepared having an aqueous phase to aromatic phasevolume proportion ranging from about 90:10 to about 40:60, preferablyfrom about 80:20 to about 50:50, or preferably from about 70:30 to about60:40.

The composition of the disclosed method may be disposed of, such as byre-injection into the subterranean formation once the chelating agent(s)of the composition become saturated with iron cations from the ironsulfide scale. Because a large volume of the composition is sometimesneeded to remove iron sulfide scale deposits and particularly becausethe costs of the chelating agent(s) in the composition may be high, itmay be advantageous to reclaim and reuse the chelating agent(s) from thespent composition. Thus, in some embodiments, the method of the presentdisclosure may further comprise acidifying the composition containingthe dissolved iron sulfide scale to form a precipitant of the at leastone chelating agent and a precipitant of at least one insoluble ironsalt, isolating the precipitant of the at least one chelating agent andthe precipitant of at least one insoluble iron salt from thecomposition, selectively dissolving the precipitated at least onechelating agent in another composition, and removing the precipitated atleast one insoluble iron salt from the another composition.

Specifically, following the contacting of the composition with the ironsulfide scale and saturation of the chelating agent(s) with the ironcations from the scale, the spent composition may be acidified to a pHof about 0-1. The acidification of the spent composition inprecipitating the chelating agent(s) out of the spent composition may beachieved by the addition of a mineral or strong acid. In one embodiment,the acid may include at least one of hydrochloric acid, nitric acid,hydrobromic acid, hydroiodic acid, formic acid, hydrofluoric acid,sulfuric acid, and chloric acid. In another embodiment, hydrochloricacid alone is used to acidify the spent composition. In still anotherembodiment, sulfuric acid may be used alone or in combination with atleast hydrochloric acid to acidify the spent composition.

As the pH is reduced, the availability of anions with which thesequestered cations, e.g. Fe²⁺ and Fe³⁺, may react may allow the cationsto be released from the chelated complex to form one or more insolubleiron salts that will precipitate out of the composition. The reductionof the pH to about 0-1 may also cause the chelating agent(s) toprecipitate out of the composition in its acid form. Since iron (III)compounds are generally more insoluble than iron (II) compounds even inan acidic solution, to reduce the mass of the insoluble iron salt(s) andfacilitate the recovery of the chelating agent(s), prior to orconcurrent with the acidification, one or more iron reducing agents,such as erythorbic acid, ascorbic acid, and stannous chloride, may beoptionally added to the spent composition to reduce Fe³⁺ being releasedfrom the chelated complex to Fe²⁺, the salt(s) of which will more likelyremain in the soluble fraction of the composition and separate from theprecipitate of the chelating agent(s). According to U.S. Pat. No.4,574,050, which is incorporated herein by reference in its entirety,erythorbic acid or ascorbic acid may be used at a concentration of 2400mg/l to be effective. Additionally, at least one hydrogen sulfidescavenger may also be added to make the sulfide unavailable forre-formation and/or re-precipitation of ferric sulfide and ferroussulfide. Non-limiting examples of suitable hydrogen sulfide scavengersinclude a reaction product of glyoxal and a polyamine disclosed in U.S.Patent Application No. US20120329930 A1 (incorporated herein byreference in its entirety), a functionalized alpha-hydroxy alkyl etherdisclosed in U.S. Patent Application No. US20140166282 A1 (incorporatedherein by reference in its entirety), and a polyaliphatic amine havingthe formula H₂NRNH—(RNH)n-H I, wherein R is an aliphatic radical and nis from about 0 to about 15, disclosed in U.S. Patent Application No.US2009/033995 (incorporated herein by reference in its entirety), etc.

The precipitated chelating agent(s) and iron salt(s) may then beisolated from the remainder of the composition. Isolation of theprecipitants may be performed by filtering the solids or decanting thesolution off the solids, or siphoning, for example. Once isolated fromthe remainder of the composition, the solids may be introduced intoanother composition containing water and/or one or more of theconverting agents (e.g. potassium carbonate) with a pH of about 5-7, orabout 6, to selectively dissolve the precipitated chelating agent(s)while limiting the ability of the chelating agent(s) to re-chelate anddissolve the precipitated iron salt(s). Once the chelating agent(s) havebecome selectively redissolved, the still-precipitated iron salt(s) maybe separated from the another composition by, for example, filtration,decantation, and/or siphoning for disposal.

In one embodiment, the another composition containing the redissolvedchelating agent(s) may be reused to remove an iron sulfide scale. Priorto reuse of the chelating agent(s) in the another composition andfollowing removal of the insoluble iron salt(s), in one embodiment, whenthe chelating agent(s) to be reused is at least one selected from thegroup consisting of DTPA, EDTA, HEDTA, and CDTA, and salts thereof, thepH of the another composition is raised to a pH in the range of 8-14,preferably 10-14, or more preferably 11-14. In one embodiment, the pH ofthe another composition is raised by adding an additional amount of theconverting agent(s) (e.g. potassium carbonate and/or potassiumbicarbonate) to the another composition. In another embodiment, the pHof the another composition is raised by adding an alkali hydroxide tothe another composition. One of ordinary skill in the art will recognizethat the amount of the converting agent(s) to be added will depend uponthe particular converting agent(s) used and the desired pH of theanother composition. In another embodiment, when the chelating agent(s)to be reused is at least one selected from the group consisting of GLDAand MGDA, and salts thereof, the pH of the another composition may beadjusted to between about 2 and about 6, preferably between about 3 andabout 5, or more preferably between about 3 and about 4. If smallquantities of the chelating agent(s) are lost in the reclaiming process,small amounts may be added for subsequent reuse cycles so that recyclingof the chelating agent(s) may be achieved without a loss in the ironsulfide scale removal efficiency in successive cycles.

A second aspect of the disclosure relates to a preferred method ofremoving an iron sulfide scale from a surface in fluid communicationwith a wellbore and/or subterranean formation. The method comprisescontacting the iron sulfide scale on the surface in fluid communicationwith the wellbore and/or subterranean formation with a composition todissolve the iron sulfide scale in the composition. The iron sulfidescale is at least one selected from the group consisting of a scale ofpyrrhotite (Fe₇S₈), a scale of troilite (FeS), a scale of marcasite(FeS₂), a scale of pyrite (FeS₂), a scale of greigite (Fe₂S₄), and ascale of mackinawite (Fe₉S₈). The composition comprises (a) DTPA and/orsalts thereof, and (b) potassium carbonate (K₂CO₃). In the composition,the weight ratio of (a):(b) lies in the range 7-60:2-20, and the pH ofthe composition is about 11-14.

In one embodiment, the preferred method may further comprise treatingthe composition containing the dissolved iron sulfide scale with aneffective amount of at least one iron reducing agent to reduce Fe³⁺ toFe²⁺, acidifying the composition containing the dissolved iron sulfidescale to form a precipitant of DTPA and/or a precipitant of at least oneinsoluble iron salt, isolating the precipitated DTPA and/or theprecipitated at least one insoluble iron salt from the composition,selectively dissolving the precipitated DTPA in another composition,and/or removing the precipitated at least one insoluble iron salt fromthe another composition. The another composition to selectively dissolvethe precipitated DTPA may preferably comprise water and potassiumcarbonate at a pH of about 5-7, or preferably about 6, and may be raisedto a pH of about 11-14 following the removal of the at least oneinsoluble iron salt and prior to using the another composition to removeiron sulfide scale deposits.

In some embodiments, the composition in contact with the iron sulfidescale forms a liquid phase, either on its own or in combination withother fluids. In either case, the preferred method may further comprisesonicating the liquid phase comprising the composition in contact withthe iron sulfide scale at a frequency of about 1-50 kHz, or preferablyabout 1-30 kHz, or preferably about 1-20 kHz, and at a power of about1-300 kW, preferably about 1-200 kW, or preferably 1-100 kW, orpreferably 1-50 kW, or preferably 1-25 kW, for a duration (e.g. tens ofhours or continuous) effective to remove or reduce the iron sulfidescale.

In some embodiments, the composition of the method can further comprise(c) at least one formate salt selected from the group consisting ofpotassium formate and cesium formate, and the weight ratio of(a):(b):(c) lies in the range 7-60:2-20:2-20. The at least one formatesalt used together with potassium carbonate may increase the efficiencyof iron cation chelation by the chelating agent(s) so that the effectivedissolution capacity of the composition for the iron sulfide scale isincreased.

Similar to the method of the first aspect of the disclosure, thispreferred method can be implemented in numerous different ways andenvironments, and the composition of this method can have any of theadditional components and combinations thereof that the composition ofthe method of the first aspect may include, as described herein.

Having generally described this invention, a further understanding canbe obtained by reference to certain specific examples which are providedherein for purposes of illustration only and are not intended to belimiting unless otherwise specified.

Example 1 Preparation of the Iron Sulfide Scale Removing Composition andDetermination of the Solubility of Pyrite (FeS₂) Scale Particles in theRemoving Composition

The iron sulfide scale removing composition was prepared by dissolvingthe chelating agent diethylene triamine pentaacetic acid (DTPA) and theconverting agent potassium carbonate (K₂CO₃) in water to reach the finalconcentration of 0.5 M and 0.43 M, respectively, and adjusting the pH ofthe solution to 12-13 with a concentrated potassium hydroxide solution.

Pyrite (FeS₂) scale particles collected from the field were then mixedwith and let soak in the above iron sulfide scale removing compositionin various ratios (grams of the pyrite scale particles to milliliters ofthe removing composition) for 24, 48, or 72 hours at 70° C. to determinethe solubility of the pyrite scale particles and the dissolution/removalefficiency of the removing composition under each condition.

FIG. 1 shows the mixture of the pyrite scale particles and the removingcomposition in a flask at the beginning of the soaking treatment. Theaqueous removing composition had a yellowish color and was mostly clear.FIG. 2 is a top view of the mixture in the flask showing the initialquantity of the input pyrite scale particles present in the mixture atthe beginning of the soaking treatment.

The pyrite scale particle dissolution/removal efficiency was determinedbased on the weight of the pyrite scale particles before and after thesoaking treatment with the removing composition. The removingcomposition was able to dissolve/remove about 70% of the pyrite scaleparticles after 24 hours of soaking treatment at 70° C., with thesolubility being 2 grams of the pyrite scale particles per 100 ml of theremoving composition. FIG. 3 shows the mixture of the pyrite scaleparticles and the removing composition in the flask after 24 hours ofsoaking treatment. The mixture had a darker color due to the dissolutionof the pyrite scale particles in the removing composition. FIG. 4 is thecorresponding top view of the mixture in the flask, showing the reducedquantity of the pyrite scale particles remaining in the mixture in theflask after 24 hours of soaking treatment as compared with the initialinput quantity of the pyrite scale particles shown in FIG. 2.

The pyrite scale particle dissolution/removal efficiency reached about80% after 48 hours of soaking treatment at 70° C., and reached about 90%after 72 hours of soaking treatment at 70° C. FIG. 5 shows the mixtureof the pyrite scale particles and the removing composition in the flaskafter 48 hours of soaking treatment, and FIG. 6 is the corresponding topview of the mixture in the flask. Referring to FIG. 5, the color of themixture following the 48-hour soaking treatment was even darker andturning black as compared with the color of the mixture following the24-hour soaking treatment shown in FIG. 3, indicating further increaseddissolution of the pyrite scale particles in the removing compositionwith the additional treatment time. Referring to FIG. 6, the quantity ofthe pyrite scale particles remaining in the mixture in the flask after48 hours of soaking treatment was further reduced as compared with thequantity of the pyrite scale particles remaining after 24 hours ofsoaking treatment shown in FIG. 4, consistent with the increaseddissolution of the pyrite scale particles.

Example 2 Determination and Comparison of the Pyrite Scale RemovalEfficiencies of the Removing Composition (DTPA/Converter), DTPA, a LowpH BDCA Solution, and 20 wt % HCl

The pyrite scale removal efficiencies of 0.5 M DTPA (pH 12-13), a low pHbio-degradable chelating agent (BDCA) solution comprising 0.5M GLDA at apH of 3-4, and 20 wt % HCl were likewise determined in parallel with theremoving composition (DTPA/Converter) following a 48-hour soakingtreatment at 70° C., with the results presented in FIG. 7. The removingcomposition (DTPA/Converter) exhibited the highest pyrite scale removalefficiency of 85%, followed by, in descending order, 0.5 M DTPA with a45% removal efficiency, the low pH BDCA solution with a 35% removalefficiency, and 20 wt % HCl with a 20% removal efficiency.

The invention claimed is:
 1. A method of removing an iron sulfide scalefrom a surface in fluid communication with a wellbore and/orsubterranean formation, comprising: contacting the iron sulfide scale onthe surface in fluid communication with the wellbore and/or subterraneanformation with a composition to dissolve the iron sulfide scale in thecomposition, wherein the composition comprises: (a) at least onechelating agent selected from the group consisting of DTPA, EDTA, HEDTA,GLDA, CDTA, and MGDA, and salts thereof, and (b) at least one convertingagent selected from the group consisting of potassium carbonate (K₂CO₃),potassium formate (HCOOK), potassium hydroxide (KOH), potassium chloride(KCl), cesium formate (HCOOCs), and cesium chloride (CsCl), (c) a liquidaromatic solvent as a dispersed phase for solid or semisolid organicmaterials, and (d) an effective amount of at least one emulsifier toform an emulsion, wherein a weight ratio of the at least one chelatingagent and the at least one converting agent lies in the range 7-60:2-20and wherein the at least one chelating agent and the at least oneconverting agent are dissolved in an aqueous solution as a continuousphase.
 2. The method of claim 1, further comprising: acidifying thecomposition containing the dissolved iron sulfide scale to form aprecipitant of the at least one chelating agent and a precipitant of atleast one insoluble iron salt, isolating the precipitant of the at leastone chelating agent and the precipitant of at least one insoluble ironsalt from the composition, selectively dissolving the precipitated atleast one chelating agent in another composition, and removing theprecipitated at least one insoluble iron salt from the anothercomposition.
 3. The method of claim 1, wherein the composition comprisesat least one chelating agent selected from the group consisting of DTPA,EDTA, HEDTA, and CDTA, and salts thereof, and wherein the compositionhas a pH ranging from about 8 to
 14. 4. The method of claim 1, whereinthe iron sulfide scale is at least one selected from the groupconsisting of a scale of pyrrhotite (Fe₇S₈), a scale of troilite (FeS),a scale of marcasite (FeS₂), a scale of pyrite (FeS₂), a scale ofgreigite (Fe₂S₄), and a scale of mackinawite (Fe₉S₈).
 5. The method ofclaim 1, wherein at least about 70% of the iron sulfide scale is removedfrom the surface in fluid communication with the wellbore and/orsubterranean formation.
 6. The method of claim 5, wherein at least 50 mlof the composition is used per gram of the iron sulfide scale.
 7. Themethod of claim 1, wherein the wellbore has a bottom hole temperature inthe range of from about 100° F. to about 400° F.
 8. The method of claim1, wherein the contacting lasts at least, about 24 hours.
 9. The methodof claim 8, wherein at least 50 ml of the composition is used per gramof the iron sulfide scale.
 10. The method of claim 1, wherein thecomposition further comprises at least one surfactant.
 11. The method ofclaim 1, wherein the liquid aromatic solvent comprises at least oneselected from the group consisting of toluene, benzene, and xylene. 12.The method of claim 1, wherein the at least one emulsifier comprises atleast one selected from the group consisting of a polyamide emulsifierhaving the formula R³O—C(O)—R⁴—C(O)—N(R¹)—(CH₂)_(n)—NH—C(O)—R² (where R¹and R² are independently selected from C₁₀-C₂₄ alkylene groups, R³ is ahydrogen or a C₁-C₅ alkyl group, R⁴ is a C₁-C₅ alkyl/alkene group, and nis an integer of from 2-5), a phosphate ester of an ethoxylated straightchain alcohol containing 8 to 10 carbon atoms and containing ethyleneoxide in reacted form at a 4:1 or greater molar ratio relative to thestraight chain alcohol, and a phosphate ester of an ethoxylated tridecylalcohol containing ethylene oxide in reacted form at a 6:1 or greatermolar ratio relative to the tridecyl alcohol.
 13. The method of claim 1,wherein a volume proportion of the aqueous solution as the continuousphase to the liquid aromatic solvent as the dispersed phase ranges fromabout 80:20 to about 50:50.
 14. The method of claim 1, wherein thewellbore is present in at least one of an oil well, a gas well, aproduction well, an injection well, a naturally flowing well, anartificially lifted well, a high temperature well, a steam assistedgravity drainage well, a steam injector well, and a geothermal well. 15.The method of claim 1, wherein the surface in fluid communication withthe wellbore and/or subterranean formation comprises a surface of an oiland/or gas reservoir, a geological surface, and/or a surface of at leastone piece of equipment selected from the group consisting of heatingturbines, heat exchangers, safety valves, casings, production tubing,mandrels, pipes, separators, pumps, tubulars, vessels, completionequipment, screens, and downhole tools.
 16. A method of removing an ironsulfide scale from a surface in fluid communication with a wellboreand/or subterranean formation, comprising: contacting the iron sulfidescale on the surface in fluid communication with the wellbore and/orsubterranean formation with a composition to dissolve the iron sulfidescale in the composition, treating the composition containing thedissolved iron sulfide scale with an effective amount of at least oneiron reducing agent to reduce Fe³⁺ to Fe²⁺, acidifying the compositioncontaining the dissolved iron sulfide scale to form a precipitant ofDTPA and/or a precipitant of at least one insoluble iron salt, isolatingthe precipitated DTPA and/or the precipitated at least one insolubleiron salt from the composition, selectively dissolving the precipitatedDTPA in another composition, and/or removing the precipitated at leastone insoluble iron salt from the another composition, wherein the ironsulfide scale is at least one selected from the group consisting of ascale of pyrrhotite (Fe₇S₈), a scale of troilite (FeS), a scale ofmarcasite (FeS₂), a scale of pyrite (FeS₂), a scale of greigite (Fe₂S₄),and a scale of mackinawite (Fe₉S₈), and wherein the compositioncomprises: (a) DTPA and/or salts thereof, and (b) potassium carbonate(K₂CO₃), wherein a weight ratio of the DTPA and/or salts thereof to thepotassium carbonate (K₂CO₃) lies in the range 7-60:2-20, and wherein apH of the composition is about 11-14.
 17. The method of claim 16,further comprising sonicating the composition after the contacting andbefore the treating at a frequency of about 1-20 kHz and at a power ofabout 1-100 kW for a duration effective to form a liquid phase incontact with the iron sulfide scale thereby removing or reducing theiron sulfide scale.
 18. The method of claim 16, wherein the compositionfurther comprises (c) at least one formate salt selected from the groupconsisting of potassium formate and cesium formate, and wherein a weightratio of the DTPA and/or salts thereof to the potassium carbonate(K₂CO₃) to at least one formate salt lies in the range 7-60:2-20:2-20.